It is known to conduct fracturing or other stimulation procedures in a wellbore by isolating zones of interest, (or intervals within a zone), in the wellbore, using packers and the like, and subjecting the isolated zone to treatment fluids, including liquids and gases, at treatment pressures. In a typical fracturing procedure for a cased wellbore, for example, the casing of the well is perforated to admit oil and/or gas into the wellbore and fracturing fluid is then pumped into the wellbore and through the perforations into the formation. Such treatment opens and/or enlarges drainage channels in the formation, enhancing the producing ability of the well. For open holes that are not cased, stimulation is carried out directly in the zones or zone intervals.
It is typically desired to stimulate multiple zones in a single stimulation treatment, typically using onsite stimulation fluid pumping equipment. A series of packers in a packer arrangement is inserted into the wellbore, each of the packers located at intervals for isolating one zone from an adjacent zone. It is known to introduce a ball into the wellbore to selectively engage one of the packers in order to block fluid flow therethrough, permitting creation of an isolated zone uphole from the packer for subsequent treatment or stimulation. Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent packer, uphole of the previously blocked packer, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Typically the balls range in diameter from a smallest ball, suitable to block the most downhole packer, to the largest diameter, suitable for blocking the most uphole packer.
At surface, the wellbore is fit with a wellhead including valves and a pipeline connection block, such as a frachead, which provides fluid connections for introducing stimulation fluids, including sand, gels and acid treatments, into the wellbore. Conventionally, operators manually introduce balls to the wellbore through an auxiliary line, coupled through a valve, to the wellhead. The auxiliary line is fit with a valved tee or T-configuration connecting the wellhead to a fluid pumping source and to a ball introduction valve. The operator closes off the valve at the wellhead to the auxiliary line, introduces one ball and blocks the valved T-configuration. The pumping source is pressurized to the auxiliary line and the wellhead valve is opened to introduce the ball. This procedure is repeated manually, one at a time, for each ball. This operation requires personnel to work in close proximity to the treatment lines through which fluid and balls are pumped at high pressures and rates. The treatment fluid is typically under high pressure and gas energized, and may be corrosive which is very hazardous.
Aside from being a generally hazardous practice, other operational problems may occur, such as valves malfunctioning and balls becoming stuck and not being pumped downhole. These problems have resulted in failed well treatment operations, requiring re-working which is very costly and inefficient. At times re-working or re-stimulating of a well formation following an unsuccessful stimulation treatment may not be successful, which results in production loss.
Other alternative methods and apparatus for the introduction of the balls have included an array of remote valves positioned onto a multi-port connection at the wellhead with a single ball positioned behind each valve. Each valve requires a separate manifold fluid pumper line and precise coordination both to ensure the ball is deployed and to ensure each ball is deployed at the right time in the sequence, throughout the stimulation operation. The multi-port arrangement, although workable, has proven to be very costly and inefficient. Further, this arrangement is dangerous to personnel due to the multiplicity of lines under high pressure connected to the top the wellhead during the stimulation operation. The multiplicity of high pressure lines also logistically limits the amount of balls that can be dropped due to wellhead design and available ports.
Larger packer balls also require specialty large bore launchers and related fracturing iron or fracturing piping which, in many cases, are not readily available and costly to procure. For example 3″ fracturing fluid piping is common but for larger balls 4″ and even 5″ pipe is required, typically having lower pressure ratings and significantly increasing the weight of the piping assembly and related high pressure capable valves and fittings. Thus, the burden to use external piping for launching larger balls quickly becomes unworkable.
It is known to feed a plurality of perforation-sealing balls using an automated device as set forth in U.S. Pat. No. 4,132,243 to Kuus. Same-sized balls are used for sealing perforations and are able to be fed one by one from a stack of balls. The apparatus appears limited to same-sized balls and there is no positive identification whether a ball was successfully indexed from the stack for injection.
Applicant has set forth a more reliable injector as set forth in published U.S. Patent Application 2008/0223587, published on Sep. 18, 2008. While addressing many of the above issues, the apparatus still retains a measure of mechanical complexity.
In another prior art arrangement, such as that set forth in FIG. 1, a vertically stacked manifold of pre-loaded balls is oriented in a bore above the wellbore of a wellhead and frac head. Each ball is temporarily supported by a rod or finger. Each finger is sequentially actuated to withdraw from the bore when required to release or launch the next largest ball. As the balls are already stacked in the bore, the lowest ball (closest to the wellbore) is necessarily the smallest ball.
It is not uncommon for a ball to be damaged or to disintegrate upon arrival at the downhole tool requiring a replacement ball or one of the same diameter to be reloaded and launched again. In the apparatus of FIG. 1, the entire apparatus must be depressurized, removed and reloaded to get a small ball under the remaining loaded balls. This requires time consuming and properly managed procedures to maintain safe control in a hazardous environment and to complete testing and re-pressurization procedures upon reinstallation to the wellhead.
More particularly, on occasions, a packer ball can be damaged while enroute to the packer. Further, pumping of displacement fluid through unit can also damage or scar balls, especially if the displacement fluid is sand-laden fracturing fluid. Damaged and scarred packer balls typically fail to isolate the zone requiring an operator to then drop an identical ball down the bore of the injector. The apparatus bore of FIG. 1 is restricted, and therefore requires the entire unit to be removed, the replacement ball dropped, the unit reassembled, and pressure tested. This is extremely inefficient, time consuming, costly and can adversely compromise the treatment.
There remains a need for a safe, efficient and remotely operated apparatus and mechanism for introducing balls to a wellbore.